Embodiments of the present invention relate, generally, to the field of sensing the properties of a liquid layer in a downhole environment. More particularly, but not by way of limitation, some embodiments provide an apparatus and a method that includes an arrangement of a sensing means providing for measurement of the flow rate of a liquid annulus layer on a casing/tubing wall of a downhole section of a well/borehole.
When exploiting subterranean fluid deposits containing hydrocarbons, downhole services such as production logging (“PC”) may be used to determine the properties within the wellbore. Such techniques ascertain the nature and behavior of fluids in or around the wellbore/borehole during production or injection. The data generated from production logging techniques, on further processing of the generated data, may be used to determine dynamic well performance and the productivity or infectivity of different zones within the wellbore/borehole, such that problem wells may be diagnosed, the results of stimulation within a well may be monitored and/or the like.
One technique common to a production logging is the use of a full-bore spinner, which when arranged as a first sensor in a production logging tool string, can measure, for example, the flow rate by means of the rate of rotation of the spinner. In essence, the spinner may form part of a flowmeter and may be used at different well depths to generate a flow profile for the well. Additionally, these flowmeters may be associated with borehole flow measurement sensors which may comprise electrical impedance sensors and/or optical probes. However, in determining the characteristics of the well, standardization of capability tends to approach a lowest common denominator, such that inaccurate measurements are generated when measuring thin liquid layers on the casing wall of the wellbore, which may, for example, be in the range of the order of millimeters thick.
As is generally known, in some flows, such as high gas flows or the like, a liquid layer on the casing wall of a well may be of the order of less than 10 millimeters, of the order of less than 5 millimeters or even of the order of less than 1 or 2 millimeters, with most of the liquid mass being in the liquid annulus with liquid droplets entrained in the gas core.
The gas/liquid flow regime in such flows is often annular with a gas core and a liquid annulus layer flowing on the production casing wall.
Moreover, a liquid layer of a liquid annulus in an annular flow often occurs in an oil or gas well having a high gas volumetric flow rate and low liquid fraction.
However, to obtain a signal representative of the flow rate of the liquid annulus on the casing wall that is both accurate and precise, sensors are required to contact the liquid to perform the measurement. In such a configuration, the sensors are likely to incur damage when placed too close to the casing wall.
That is, while techniques exist for measuring the flow rate of the gas core, even the liquid droplet concentration entrained in the gas, as in a wet gas flow, it remains a challenge to measure the flow rate of the annular liquid flow on the casing wall in an annular flow regime.
For example, U.S. Pat. No. 4,947,683 (Minear et al.) discloses a measuring device for use in a producing well comprising a sonde having upper and lower centralizers to define an annular flow space therearound. A motor driven sensor such as a piezoelectric combination transmitter and receiver is included to transmit and then receive ultrasonic pulses. They are transmitted downwardly from the housing into fluid flowing in the well. Reflective interfaces are defined by material differences. Gas bubbles droplets and particles in the fluid flow and phases between oil and water form reflective interfaces to create a scattering effect to transmitted ultrasonic pulses so that a return pulse is formed. The pulses encode fluid flow velocity as a result of the Doppler shift.
Similarly, U.S. Pat. No. 5,736,637 (Evans et al) discloses a system for evaluating multiphase flow of a fluid downhole in a borehole. Dielectric permittivity electrodes generate a capacitance output signal through the fluid, and conductivity electrodes generate a conductivity output signal through the fluid. The electrodes are powered with an alternating current (AC) generator operating at the same or different frequencies. The capacitance and conductivity output signals can be alternately generated by operating a controller, and such signals can be combined with a multiplexer engaged with the controller. The signal can be processed downhole or can be transmitted to a receiver positioned at the well surface for processing and interpretation of the multiphase data.
However, in both publications the use of the respective ultrasonic or capacitive sensors are only used in downhole measurements of non-annular flows and are thus only appropriate for flow regimes other than an annular flow regime.
Further, for an ultrasonic sensor, the propagation loss and the signal attenuation increases exponentially with the travel distance in the gas phase, (d), which is considered to be the distance between the sensor and the liquid layer. For a capacitance sensor, the measurement sensitivity is affected by the reciprocal of the distance, 1/d. However, placement of the sensors against the tubing wall would incur damage to the sensors.
Accordingly, a need exists to measure the velocity of the liquid layer without causing damage to the production logging sensors, such that a liquid production profile is generated for wells with an annular flow regime, and further the identification of condensate/oil and water.
Further, a need exists to determine what type of liquid is produced, and from which location within the well, so that the production of hydrocarbons from the well can be managed and/or accurately measured/assessed.
A further need exists to continuously measure the total flow rate of the liquid annulus on the casing wall that is both accurate and precise.
Furthermore and due to the variable environment within a wellbore and the different flow rates of the liquid at different locations within the bore, it is additionally required to calibrate the production logging tool that corrects for this variability.